US10935682B2 - Downhole seismic sensing synchronization systems and methods - Google Patents
Downhole seismic sensing synchronization systems and methods Download PDFInfo
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- US10935682B2 US10935682B2 US15/712,546 US201715712546A US10935682B2 US 10935682 B2 US10935682 B2 US 10935682B2 US 201715712546 A US201715712546 A US 201715712546A US 10935682 B2 US10935682 B2 US 10935682B2
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- 238000000034 method Methods 0.000 title claims description 34
- 230000015572 biosynthetic process Effects 0.000 claims description 21
- 230000005540 biological transmission Effects 0.000 claims description 11
- 238000001514 detection method Methods 0.000 claims description 11
- 238000004891 communication Methods 0.000 claims description 4
- 230000003466 anti-cipated effect Effects 0.000 claims 4
- 238000005755 formation reaction Methods 0.000 description 16
- 238000005553 drilling Methods 0.000 description 15
- 238000010586 diagram Methods 0.000 description 12
- 239000012530 fluid Substances 0.000 description 6
- 230000003287 optical effect Effects 0.000 description 3
- 238000003491 array Methods 0.000 description 2
- 230000001360 synchronised effect Effects 0.000 description 2
- 238000012360 testing method Methods 0.000 description 2
- 230000003213 activating effect Effects 0.000 description 1
- 239000004020 conductor Substances 0.000 description 1
- 238000005520 cutting process Methods 0.000 description 1
- 238000010348 incorporation Methods 0.000 description 1
- 238000012544 monitoring process Methods 0.000 description 1
- 238000012545 processing Methods 0.000 description 1
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- 238000012795 verification Methods 0.000 description 1
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/24—Recording seismic data
- G01V1/26—Reference-signal-transmitting devices, e.g. indicating moment of firing of shot
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/003—Seismic data acquisition in general, e.g. survey design
- G01V1/005—Seismic data acquisition in general, e.g. survey design with exploration systems emitting special signals, e.g. frequency swept signals, pulse sequences or slip sweep arrangements
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/28—Processing seismic data, e.g. for interpretation or for event detection
- G01V1/30—Analysis
- G01V1/301—Analysis for determining seismic cross-sections or geostructures
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V1/00—Seismology; Seismic or acoustic prospecting or detecting
- G01V1/40—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging
- G01V1/42—Seismology; Seismic or acoustic prospecting or detecting specially adapted for well-logging using generators in one well and receivers elsewhere or vice versa
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2200/00—Details of seismic or acoustic prospecting or detecting in general
- G01V2200/10—Miscellaneous details
- G01V2200/12—Clock synchronization-related issues
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2200/00—Details of seismic or acoustic prospecting or detecting in general
- G01V2200/10—Miscellaneous details
- G01V2200/14—Quality control
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- G—PHYSICS
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- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2210/00—Details of seismic processing or analysis
- G01V2210/10—Aspects of acoustic signal generation or detection
- G01V2210/12—Signal generation
- G01V2210/121—Active source
- G01V2210/1214—Continuous
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2210/00—Details of seismic processing or analysis
- G01V2210/10—Aspects of acoustic signal generation or detection
- G01V2210/12—Signal generation
- G01V2210/129—Source location
- G01V2210/1295—Land surface
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2210/00—Details of seismic processing or analysis
- G01V2210/10—Aspects of acoustic signal generation or detection
- G01V2210/14—Signal detection
- G01V2210/142—Receiver location
- G01V2210/1429—Subsurface, e.g. in borehole or below weathering layer or mud line
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V2210/00—Details of seismic processing or analysis
- G01V2210/10—Aspects of acoustic signal generation or detection
- G01V2210/16—Survey configurations
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- G—PHYSICS
- G06—COMPUTING; CALCULATING OR COUNTING
- G06F—ELECTRIC DIGITAL DATA PROCESSING
- G06F30/00—Computer-aided design [CAD]
- G06F30/20—Design optimisation, verification or simulation
Definitions
- seismic sensing devices e.g., a receiver or sensor
- seismic signals e.g., vibration
- the seismic signals can be indicative of characteristics of the surrounding environment.
- seismic sensing devices can be used in various contexts, such as a downhole tool.
- multiple seismic sensing devices can be employed to facilitate conducting micro-seismic surveys, for example, to determine event hypocenter locations and/or moment tensor inversion solutions. Yet coordinating the operation of the multiple seismic sensing devices can be frustrated by variations in operation of these different components.
- a seismic system that includes a seismic source configured to generate a first seismic signal and a second seismic signal in a formation adjacent the seismic source.
- the seismic system can also include a first downhole sensing device disposed in a first borehole configured to detect the first seismic signal and the second seismic signal in the formation.
- a first surface acquisition system can be communication with the first downhole sensing device. The first surface acquisition system can be configured to: determine a first reference transit time based at least in part on detection of the first seismic signal by the first downhole sensing device; determine a first subsequent transit time based at least in part on detection of the second seismic signal by the first downhole sensing device; and determine whether a synchronization variation is expected to be present based at least in part on the first reference transit time and the first subsequent transit time.
- a method of performing a seismic operation can include generating a first seismic signal and a second seismic signal in a formation adjacent the seismic source.
- the method can also include detecting the first seismic signal and the second seismic signal in the formation.
- the method also includes determining a first reference transit time based at least in part on detection of the first seismic signal, and determining a first subsequent transit time based at least in part on detection of the second seismic signal; and determining whether a synchronization variation is expected to be present based at least in part on the first reference transit time and the first subsequent transit time.
- FIG. 1 depicts a schematic diagram of a drilling system including a downhole seismic sensing device, according to one or more embodiments described.
- FIG. 2 depicts a schematic diagram of a wireline system including a downhole seismic sensing device, according to one or more embodiments described.
- FIG. 3 depicts a schematic diagram of a seismic system including multiple downhole seismic sensing devices, according to one or more embodiments described.
- FIG. 4 depicts a flow diagram of a process for determining synchronization variation between multiple downhole seismic sensing devices, according to one or more embodiments described.
- FIG. 5 depicts a flow diagram of a process for determining transit time of a seismic signal, according to one or more embodiments described.
- FIG. 6 depicts a flow diagram of a process for determining an expected cause of a synchronization variation, according to one or more embodiments described.
- a seismic sensing device can receive seismic signals to facilitate determining characteristics of its surrounding environment.
- seismic sensing devices can be used in various contexts.
- the present disclosure presents techniques described in a downhole context or downhole environment. It should be appreciated that this is illustrative and not limiting. In other words, the techniques described in the present disclosure can be applied in other suitable contexts or environments.
- FIGS. 1 and 2 depict examples of different systems for conveying seismic sensing devices. More particularly, FIG. 1 depicts a schematic diagram of a drilling system 10 that includes a downhole seismic sensing device 42 and FIG. 2 depicts a schematic diagram of a wireline system 52 that includes the downhole seismic sensing device 42 , according to one or more embodiments.
- the drilling system 10 can be used to drill a well through sub-surface formations 12 .
- a drilling rig 14 at the surface 16 can rotate a drill string 18 , which includes a drill bit 20 at its lower end to engage the subsurface formation 12 .
- a drilling fluid pump 22 can pump drilling fluid, commonly referred to as “mud” or “drilling mud,” downward through the center of the drill string 18 in the direction of the arrow 24 to the drill bit 20 , which can cool and/or lubricate the drill bit 20 .
- the drilling fluid can exit the drill string 18 through ports (not shown).
- the drilling fluid can then flow through an annulus 30 between the drill string 18 and the formation 12 in the direction of arrows 28 toward the surface 16 . In this manner, the drilling fluid can carry drill cuttings away from the bottom of a borehole 26 . Once at the surface 16 , the returned drilling fluid can be filtered and conveyed back to a mud pit 32 for reuse.
- a lower section of the drill string 18 can include a bottom-hole assembly 34 that can include the drill bit 20 along with one or more downhole tools 40 , such as a measuring-while-drilling (MWD) tool 36 and/or a logging-while-drilling (LWD) tool 38 .
- the downhole tools 40 can facilitate determining one or more characteristics of the surrounding formation 12 .
- the downhole tools 40 can include various sensing devices (e.g., sensors), such as a seismic sensing device 42 that detects seismic signals in the formation 12 .
- the seismic sensing device 42 can include one or more acoustic receiving units which can each include one or more acoustic receivers.
- a surface acquisition system 44 can operate as a control system to control operation of the downhole tool 40 .
- the surface acquisition system 44 can instruct the seismic sensing device 42 to detect seismic signals and/or receive sensor data indicative of the detected seismic signals from the seismic sensing device 42 .
- the downhole tool 40 can communicate the determined information to the surface acquisition system 44 for further processing.
- wireless transceivers 50 / 51 can be used to transmit information between the downhole tool 40 and the surface acquisition system 44 .
- one or more wires, optical cables, or physical connection can be used to transmit information between the downhole tool 40 and the surface acquisition system 44 .
- the surface acquisition system 44 can include one or more processors 46 and one or more memory 48 , and/or the downhole tools 40 can include one or more processors 47 and one or more memory 49 .
- the processor(s) 46 / 47 can include one or more general purpose microprocessors, one or more application specific processors (ASICs), one or more field programmable logic arrays (FPGAs), or any combination thereof.
- the memory(s) 48 / 49 can be a tangible, non-transitory, computer-readable medium that can store instructions executable by and data that can be processed by the processor(s) 46 / 47 .
- the memory(s) 48 / 49 can include random access memory (RAM), read only memory (ROM), rewritable flash memory, hard drives, optical discs, and the like.
- the downhole tool 40 including the seismic sensing device 42 can be used in a wireline system 52 as shown in FIG. 2 .
- the wireline system 52 can include a wireline assembly 54 suspended in the borehole 26 and coupled to a surface acquisition system 44 via a cable 56 , for example, transmit or convey information gathered by the seismic sensing device 42 to the surface acquisition system 44 .
- the wireline assembly 54 can include various downhole tools 40 .
- the downhole tools 40 can include a telemetry tool 58 and a formation testing tool 60 .
- the surface acquisition system 44 can control operation of the various downhole tools 40 .
- the surface acquisition system 44 can include one or more processors 46 and one or more memory 48
- the formation testing tool 60 can include one or more processors 47 and one or more memory 49 .
- the processor(s) 46 / 47 can include one or more general purpose microprocessors, one or more application specific processors (ASICs), one or more field programmable logic arrays (FPGAs), or any combination thereof.
- the memory(s) 48 / 49 can be a tangible, non-transitory, computer-readable medium that stores instructions executable by and data to be processed by the processor(s) 46 / 47 .
- the memory(s) 48 / 49 can include random access memory (RAM), read only memory (ROM), rewritable flash memory, hard drives, optical discs, and the like.
- seismic sensing devices 42 can also be used in other downhole systems.
- one or more seismic sensing devices 42 can be used in a coil tubing system, a wired drill pipe system, a slick line system, or the like.
- operation of seismic sensing devices 42 can be generally similar in the downhole tools 40 .
- FIG. 3 depicts a schematic diagram of a seismic system 62 that can include multiple downhole seismic sensing devices 42 , according to one or more embodiments.
- the seismic system 62 can include multiple seismic sensing devices 42 deployed in different boreholes 26 as shown in FIG. 3 .
- a first downhole tool 40 A can include a first seismic sensing device 42 A disposed in a first borehole 26 A and communicatively coupled to a first surface acquisition system 44 A.
- a second downhole tool 40 B can include a second seismic sensing device 42 B disposed in a second borehole 26 B and communicatively coupled to a second surface acquisition system 44 B.
- the surface acquisition systems 44 A, 44 B can be implemented on one or more logging (e.g., Maxis) trucks used for the deployment of a wireline-conveyed downhole tools 40 A/ 40 B having seismic sensing (e.g., VSI, OYO, or Sercel) devices 42 A/ 42 B.
- the seismic sensing devices 42 e.g., PS3
- the surface acquisition systems 44 can be permanent systems.
- the seismic system 62 can include a seismic source 64 .
- the seismic source 64 can be any type of common vibrator and/or controlled surface source, such as an Accelerated Weight Drop or Vibrator Truck.
- the seismic source 64 can be an impulsive source or a non-impulsive source.
- the seismic source 64 can generate seismic signal 66 .
- the seismic signals 66 can be supplied to and radiate or otherwise traverse through the formation 12 .
- Characteristics (e.g., properties) of the formation 12 can be determined based, at least in part, on the seismic signals 66 received by the first and second seismic sensing devices 42 A, 42 B.
- the seismic signals 66 generated by the seismic source 64 can be any combination of amplitude and/or frequency controlled signal based at least in part on target characteristics to be determined.
- FIG. 4 depicts a flow diagram of a process 68 for determining synchronization variation between multiple downhole seismic sensing devices 42 , according to one or more embodiments.
- the process 68 can include determining a reference transit time (process block 70 ), determining a subsequent transit time (process block 72 ), determining whether the reference transit time and the subsequent transit time vary by more than a threshold (decision block 74 ), and indicating a synchronization variation when the reference transit time and the subsequent transit time vary by more than the threshold (process block 76 ).
- the process 68 can be implemented by executing instructions stored in a tangible, non-transitory, computer-readable medium, such as memory(s) 48 / 49 , using one or more processors, such as processor(s) 46 / 47 .
- the reference transit time can be determined based at least in part on transmission of an initial seismic signal 66 from the seismic source 64 .
- the subsequent transit time can be determined based at least in part on transmission of a subsequent seismic signal 66 from the seismic source 64 .
- the transit time can be determined based at least in part on a known transmission time (T0) of a synchronization seismic signal and receipt of the synchronization signal by one or more seismic sensing devices 42 .
- T0 transmission time
- the transit time(s) can be determined by subtracting T0 of the source from one or more arrival times of the synchronization signal.
- FIG. 5 depicts a flow diagram of a process 78 for determining transit time of a seismic signal 66 , according to one or more embodiments.
- the process 78 can include transmitting a seismic signal from a seismic source at a known time (process block 80 ), determining arrival time of the seismic signal at a seismic sensing device (process block 82 ), and determining transit time based at least in part on the known time and the arrival time (process block 84 ).
- the process 78 can be implemented by executing instructions stored in a tangible, non-transitory, computer-readable medium, such as memory(s) 48 / 49 , using one or more processors, such as processor(s) 46 / 47 .
- a surface acquisition system 44 can know when the seismic source 64 is expected to transmit a synchronization seismic signal. Thus, the surface acquisition system 44 can determine a relative transit time based at least in part on the known time and the arrival time at a corresponding seismic sensing device 42 . In particular, arrival time can be the transit time after the known transmission time (T0).
- the transit time determined based at least in part on transmission of an initial seismic signal 66 can be used as the reference transit time.
- the seismic source 64 can subsequently retransmit the synchronization seismic signal 66 .
- the seismic source 64 can periodically retransmit the synchronization seismic signal 66 .
- the seismic source 64 can retransmit the synchronization seismic signal 66 when a synchronization check can be desired.
- the surface acquisition systems 44 A/ 44 B and/or the downhole tools 40 A/ 40 B can determine whether synchronization variations are expected to be present in the seismic system 62 .
- the surface acquisition system 44 and/or downhole tool 40 can determine that a synchronization variation can be expected to be present when a subsequent transit time varies from the reference transit time by more than a threshold.
- the threshold can be dynamically adjusted, for example, to account for sensor error and/or to improve synchronization.
- a surface acquisition system 44 and/or downhole tool 40 can indicate that a synchronization variation can be expected to be present, thereby enable corrective measures to be employed.
- the seismic source 64 and the seismic sensing device 42 can operate in a master-slave mode, in which the initial seismic signal 66 can trigger the start of recording by the seismic sensing device 42 .
- synchronization determination can be performed based on the assumption that the seismic source 64 remains in generally the same location. In other words, in some examples, the synchronization process can be reinitiated when the seismic source 64 moves location.
- the seismic system 62 can facilitate determining one or more causes of a synchronization variation; for example, determining whether the synchronization variation is expected at the surface and/or downhole.
- FIG. 6 depicts a flow diagram of a process 86 for determining an expected cause of a synchronization variation, according to one or more embodiments.
- the process 86 can include time stamping in a surface acquisition system (process block 88 ), time stamping in a downhole sensing device (process block 90 ), and determining expected cause of a synchronization variation (process block 92 ).
- the process 86 can be implemented by executing instructions stored in a tangible, non-transitory, computer-readable medium, such as memory(s) 48 / 49 , using one or more processors, such as processor(s) 46 / 47 .
- different surface acquisition systems 44 can utilize time-stamping techniques to determine an absolute transmission time of a synchronization signal, for example, based at least in part on an indication from the seismic source 64 and/or from an external (e.g., GPS or independent) source, not shown.
- the delivery of a signal downhole with known timing can be recorded by part of the downhole system using processor(s) 46 / 47 and memory(s) 48 / 49 , ( FIGS. 1 and 2 ) and time stamped as if it came from one of the seismic sensing devices 42 A/ 42 B.
- the signal can be derived from the seismic source 64 or the external source.
- the signal can be an analog signal and can be delivered downhole by using a spare conductor in the logging cable 56 ( FIG. 2 ).
- synchronization of downhole-to-surface signals can be performed to reduce a likelihood of transmission loss from the seismic sensing device 42 to the surface acquisition system 44 .
- the seismic sensing device 42 can load a job time counter (JTC) from the surface acquisition system 44 .
- JTC job time counter
- the seismic sensing device 42 can track and update the downhole telemetry cartridge timestamp to be in sync with JTC.
- downhole timestamps can be synchronized with an absolute (e.g., GPS) timing.
- Verification can be accomplished with a time-tracking algorithm monitoring the timing information in surface and downhole telemetry components, which can facilitate identifying and correcting any synchronization variations within the downhole-to-surface telemetry (e.g., digital) path and surface-downhole time stamping within each independent recording system.
- a time-tracking algorithm monitoring the timing information in surface and downhole telemetry components, which can facilitate identifying and correcting any synchronization variations within the downhole-to-surface telemetry (e.g., digital) path and surface-downhole time stamping within each independent recording system.
- the seismic (e.g., vibrator or pilot) signal can be acquired and time stamped to facilitate improving synchronization accuracy.
- the seismic source 64 can be a non-impulsive source (i.e. vibrator)
- correlation between multiple signals can be used to determine transit times.
- the seismic source 64 is weak, seismic sensing devices 42 are insensitive or in a noisy environment, the subsurface attenuation of signals is high, and/or the distance between the seismic source 64 and the seismic sensing device 42 is far, determination accuracy can be improved by activating the seismic source 64 multiple times, gathering the signal records from associated time periods, and stacking the records to build a signal-to-noise ratio prior to determining the Transit Times.
- a seismic system comprises a seismic source configured to generate a first seismic signal and a second seismic signal in an adjacent formation; a first downhole sensing device disposed in a first borehole configured to detect the first seismic signal and the second seismic signal in the adjacent formation; and a first surface acquisition system communicatively coupled to the first downhole sensing device, where the first surface acquisition system can be configured to: determine a first reference transit time based on a known transmission time of a synchronization seismic signal and receipt of the synchronization signal by the first downhole sensing device; determine a first subsequent transit time based at least in part on detection of the second seismic signal by the first downhole sensing device; and determine whether a synchronization variation can be expected to be present based at least in part on the first reference transit time and the first subsequent transit time.
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US6912465B2 (en) * | 2002-12-12 | 2005-06-28 | Schlumberger Technology Corporation | System and method for determining downhole clock drift |
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US20110010098A1 (en) | 2008-02-25 | 2011-01-13 | China National Petroleum Corporation | Method of pre-stack two-dimension-like transformation of three-dimensional seismic record |
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US20120320712A1 (en) | 2011-06-20 | 2012-12-20 | Ahmed Adnan Aqrawi | Dip seismic attribute |
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-
2017
- 2017-09-22 US US15/712,546 patent/US10935682B2/en active Active
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US6912465B2 (en) * | 2002-12-12 | 2005-06-28 | Schlumberger Technology Corporation | System and method for determining downhole clock drift |
US20050285645A1 (en) * | 2004-06-28 | 2005-12-29 | Hall David R | Apparatus and method for compensating for clock drift in downhole drilling components |
US20110010098A1 (en) | 2008-02-25 | 2011-01-13 | China National Petroleum Corporation | Method of pre-stack two-dimension-like transformation of three-dimensional seismic record |
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